Apparatus and method for simultaneously obtaining quantitative measurements of formation resistivity and permittivity in both water and oil based mud

ABSTRACT

An apparatus and method for simultaneously obtaining quantitative measurements of vertical and horizontal resistivity and permittivity formation parameters by firing, using at least one transmitter in each of a horizontally and vertically polarized array on opposite sides of a drill collar, signals in the direction of a downhole formation, the fired signals from the transmitters in the arrays being fired simultaneously and engaging the downhole formation. The apparatus and method continues by receiving, using at least one receiver in each of the arrays, signals associated with the fired signals after the fired signals have engaged the downhole formation, where the received signals represent apparent formation data. The apparatus and method further involves determining, using the measured apparent formation data, the true formation data including one or more vertical and horizontal formation parameters.

BACKGROUND OF THE DISCLOSURE

During the exploration of oil and gas, measuring the resistivity andpermittivity of a formation downhole can provide important data forgeologist and petro physicist to evaluate formation property, such aswhether a formation contains water or hydrocarbons. Due to deposition,fractures, and the lamination of layers within a formation, etc.,formations downhole will typically exhibit some form of anisotropy. Theresistivity and permittivity anisotropy of a formation downhole canrepresent this formation anisotropy. The anisotropy has large effects onthe resistivity and permittivity measurements, which will affect theaccuracy of formation evaluation.

Anisotropy is commonly modeled using transverse isotropy (TI). Aformation will exhibit TI-anisotropy when it has an axis of symmetrysuch that along any direction parallel (or transverse) to this axis thematerial properties of the formation are the same. However, between theaxis of symmetry and a direction perpendicular to the axis of symmetry,one will see a material property difference.

Electromagnetic tools used in wireline and measurement while drilling(MWD) applications are typically used for measuring formationresistivity and dielectric permittivity. However, some electromagnetictools, such as resistivity and permittivity measurement tools, used inwireline haven't used in MWD.

Also, although these electromagnetic tools used in MWD are capable oftaking measurements while drilling, these tools are currently focused onmeasuring TI-anisotropy of a formation in one direction relative to theaxis of the tool, and cannot measure the anisotropy of a formation inmultiple directions simultaneously.

Further, another limitation of many electromagnetic tools which canoperate in water base-mud is that they cannot operate in oil based muddue to the non-conductive nature of some oil based mud. Therefore,having the ability to operate in both oil based mud and water base mudenvironment is one advantage some electromagnetic tools have overothers. By operating electrical electromagnetic tools using higherfrequencies (in the range of hundreds of Megahertz to Gigahertz), thesetools are better able to take measurements in oil based mud as well asin water base mud.

It is therefore desirable to have an apparatus and method for takingquantitative measurements of formation parameters, such as resistivityand permittivity, in multiple directions simultaneously. Moreover, it isalso desirable to be able to take quantitative measurements of theformation parameters in both water based and oil based mud. The subjectmatter of the present disclosure is directed to overcoming, or at leastreducing the effects of, one or more of the problems set forth above.

SUMMARY OF THE DISCLOSURE

The present disclosure involves an apparatus and method forsimultaneously obtaining quantitative measurements of vertical andhorizontal resistivity and permittivity by firing, using at least onetransmitter in each of a horizontally and vertically polarized array onopposite sides of a drill collar, signals in the direction of a downholeformation, the fired signals from the transmitters in the arrays beingfired simultaneously and engaging the downhole formation.

The apparatus and method continues by receiving, using at least onereceiver in each of the arrays, signals associated with the firedsignals after the fired signals have engaged the downhole formation,where the received signals represent apparent formation measurementdata.

The apparatus and method further involves determining, using themeasured apparent formation data, the true formation data including oneor more vertical and horizontal formation parameters.

The foregoing summary is not intended to summarize each potentialembodiment or every aspect of the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a downhole tool disposed in a wellbore according tothe present disclosure.

FIGS. 2A-2B illustrate vertical and horizontal antenna elementsaccording to the present disclosure.

FIG. 3 illustrates exemplary antenna arrays according to the presentdisclosure.

FIGS. 4A-4D illustrate exemplary combinations of antenna arrayconfigurations according to the present disclosure.

FIGS. 5A-5C illustrate side and cross-sectional views of a stabilizeraccording to the present disclosure.

FIG. 6 illustrates a method for simultaneously obtaining quantitativevertical and horizontal formation parameters according to the presentdisclosure.

FIG. 7 illustrates a method for determining true formation measurementdata according to the present disclosure.

DETAILED DESCRIPTION OF THE DISCLOSURE

Overview of the Apparatus

FIG. 1 illustrates a downhole tool 100 having a cylindrical bodydisposed in a wellbore 114 according to the present disclosure. Asshown, the downhole tool 100 includes a drill string 113 being disposedin a wellbore 114 from a drilling rig 110 and has a bottom hole assembly(BHA) including a drill collar 125 disposed thereon. The rig 110 alsohas draw works and other systems for controlling the drill string 113 asit advances in and out of the wellbore 114. The rig also has mud pumps(not shown) that circulate drilling fluid or drilling mud through thedrill string 113.

As shown, the drill collar 125 of the downhole tool (100) has anelectronics section 130, a mud motor 135, and an instrument section 140.Drilling fluid flows from the drill string 113 and through theelectronics section 130 to the mud motor 135. Powered by the pumpedfluid, the motor 135 imparts torque to the drill bit 145 to rotate thedrill bit 145 and advance the wellbore 114.

Also as shown, one or more centralizers 115 may be disposed on a drillcollar or on the drill string 113, and may act as a stabilizer forstabilizing the drill string 113 in the wellbore 114. Further as will bediscussed below, one or more electromagnetic antenna arrays 112 can bedisposed on the centralizers 115. However, as not to limit the antennaarrays 112 to being disposed on the centralizers 115, the arrays may bedisposed anywhere on the BHA, preferably on the drilling collar withinthe wellbore 114. Surface equipment 105 having an up hole processingunit (not shown) may also obtain and process formation measurement datafrom the electromagnetic antenna arrays disposed on the centralizers115. Typically, the surface equipment 105 may communicate data with theelectromagnetic antenna arrays and/or electronics section 130 usingtelemetry systems known in the art, including mud pulse, acoustic, andelectromagnetic systems.

Referring now to FIGS. 2A-2B, vertical and horizontal slot antennaelements (200 and 205) are illustrated according to the presentdisclosure. As discussed below, each slot antenna element (200 and 205)may be used for both transmitting and receiving electrical signals intoa wellbore 114. Also, more than one slot antenna (200 and 205) may beincluded in the electromagnetic antenna arrays 112 discussed above.

As will be appreciated by those skilled in the art, this disclosure isnot limited to a particular type of slot antenna (200 and 205) fortransmitting and/or receiving electrical signals, as any slot antennaknown in the art for transmitting and receiving electrical signals maybe used (e.g., horn antennas including a waveguide, etc.).

Also, although the present disclosure is indifferent to the type of slotantenna (200 and 205) that may be used, in order for the tool to operatein oil based mud, the slot antenna (200 and 205) must operate usinghigher frequencies. For example, in one aspect of the invention,operating slot antennas 200 may use a frequency range between 10 MHz(Megahertz) and 20 GHz (Gigahertz).

In one example, the openings of the slot antenna elements (200 and 205)may be filled with an epoxy or other non-conducting filler. This epoxyserves to protect the slot antenna elements (200 and 205) during loggingwhile drilling operations. Further, the shape of the slot antennaelements (200 and 205) is not limited to having rectangular apertures asshown, as different antenna aperture designs may be incorporated.

Now referring to FIG. 2A, because slot antenna element 200 is shownoriented vertically with respect to the Z axis (i.e., magneticallypolarized in a vertical direction) it is considered to be verticallypolarized. Thus, the vertically polarized slot antenna elements 200 canbe regarded as having vertical magnetic moments. Furthermore, as will bedescribed further below, because electrical current will traverse thevertically polarized slot antenna elements 200 along the X/Y axis, thevertically polarized slot antennas 200 are considered to have horizontalelectric moments (Eh). The horizontal or vertical orientations of theantenna elements are with respect to the axes of the drill string 113.

Likewise as shown in FIG. 2B, because the slot antenna element 205 isshown oriented horizontally along the X/Y axis, it is considered to behorizontally polarized. Also, because the magnetic polarization ofhorizontally polarized slot antenna 205 is along the X/Y axis,horizontally polarized slot antenna elements 205 can be regarded ashaving a horizontal magnetic moment. Also as will be discussed below,because electrical current will flow through the horizontally polarizedslot antennas 205 in a direction orthogonal to the direction of itsmagnetic polarization (i.e., along the Z axis), the horizontallypolarized slot antenna elements 205 are considered to have a verticalelectric moment (Ev).

FIG. 3 illustrates four exemplary electromagnetic antenna arrays 112according to the present disclosure. In one example, each antenna arrayis composed of four slot antenna elements (200 and 205), using two slotantenna elements as transmitters for transmitting (T1 and T2) or (T3 andT4), and using two slot antenna elements as receivers for receiving (R1and R2) or (R3 and R4).

Also, slot antenna transmitters T1 and T3 are interchangeable dependingon which antenna array (305-320) is referred to as the first or secondarray. Likewise, slot antenna transmitters (T2 and T4) are alsointerchangeable. For similar reasons receivers (R1 and R3) and (R2 andR4) are similarly interchangeable.

Referring again to FIG. 3, each of the antenna arrays 112 has adifferent slot antenna element (200 and 205) configuration. In oneexample according to the present disclosure, a vertically polarizedvertical array (VPVA) 305 may be composed of four vertically polarizedslot antenna elements (200). In another example, a horizontallypolarized horizontal array (HPHA) 310 is shown composed of fourhorizontally polarized slot antenna elements (205). In yet anotherexample, as shown, a vertically polarized horizontal array (VPHA) 315 isshown being composed of four vertically polarized slot antenna elements(200). Also, in another example, a horizontally polarized vertical array(HPVA) 320 is shown being composed of four horizontally polarized slotantenna elements (205).

As will be described below, each of these antenna arrays (112) (e.g.,305-320) may be used in combination with another antenna array (305-320)on an opposite pad (not shown) of the downhole tool centralizer 115, oropposite side of the drill collar. Thus, considering the rotation of thetool in the wellbore 114, the two antenna arrays (305-320) can beregarded as one tool having an equivalent, vertical and horizontal,electric moments.

That is, as the tool rotates around wellbore 114, because the antennaarrays (305-320) are disposed on opposite sides of the tool (100), theantenna arrays (305-320) can simultaneously be used to detect bi-axialproperties of the downhole formation such as the resistivity andpermittivity of the formation in both the vertical direction and at allazimuthal angle positions within the wellbore (114).

As described above, and as will be described below, each antenna array(305-320) is disposed on opposite sides of the tool's centralizer (115),and will be used to transmit electrical signals into the wellbore (114)and receive signals associated with those transmitters, after thesignals have engaged the formation downhole. One purpose for havingvertical and horizontal polarities of the antenna arrays (305-320) is sothat, based on the polarities of the antenna elements (200 and 205), thedownhole tool may simultaneously take measurements in both the verticaland horizontal directions within the wellbore (e.g. Z and X/Y axes,respectively).

To further illustrate the possible antenna array (305-320) combinations,we now refer to FIGS. 4A-4D. As shown, four exemplary combinations ofantenna array (305-320) configurations may be used according to thepresent disclosure. With reference to FIG. 4A, a HPVA 320 is shown incombination with a VPHA 315. Because in this example the polarity of theslot antennas elements (205) of the HPVA 320 is in the horizontaldirection, the polarity of the measured data will be in the horizontaldirection along the X/Y axis relative to the tool drill collar (125).Also, because the slot antenna elements (200) of the VPHA 315 of FIG. 4Aare vertically polarized, the polarity of the data will be in thevertical direction, along the Z axis relative to the drill collar (125).

In another example referring to FIG. 4B, an HPVA 320 is shown incombination with a VPVA 305. Also, in another example referring to FIG.4C, a VPVA 305 may be in combination with a HPHA 310, and in yet anotherexample referring to FIG. 4D, a HPHA 320 may be in combination with aVPHA 310. In each of these examples, as described above with referenceto FIG. 4A, the direction of the data measured by individual slotantennas (200 and 205) will vary with the direction of the polarizationof each slot antenna (200 and 205).

Now that we have discussed slot antennas (200 and 205) and thecombinations of electromagnetic array antennas (305-320) that may bedisposed on the centralizers (115) of the downhole tool (100), thedisclosure will now illustrate how the electromagnetic arrays (305-320)may be disposed on the one or more centralizers (115).

As shown in FIGS. 5A-5C, side and cross-sectional views of a centralizer115 is shown according to the present disclosure. Referring to FIG. 5A,a VPHA 310 is shown disposed on a centralizer 115. As shown, the VPHA310 is placed in the center of the centralizer's 115 pad 505, althoughthe placement of the array on the pad 505 is not limited to the center.In one example, the centralizer 115 may have many different sizes ordesigns.

Also, as shown in FIG. 5B, the centralizer 115 has four pads displacedaround the centralizer 115, being separated by 90°. The opposite sidesof the centralizer 115 is better illustrated by referring to the crosssectional view of the centralizer 115 in FIG. 5B. As shown, thecentralizer 115 has four sides separated by 90°. In one example,opposite sides of the centralizer 115 are illustrated by sides 505. Inthis example, an antenna array (305-320) may be on any side of thecentralizer 115, with any other antenna array having opposite polarity(e.g., 305-320) being on the opposite side (i.e., separated by 180°).Also, although the tool (100). has been described above having acentralizer with four sides, the tool is not limited to four sides. Thetool (100) can have many sides which would create various angles, aslong as the antenna arrays (305-320) are on sides that oppose eachother.

Also as shown in FIG. 5A, a wire 515 carrying electrical current isconnected to the VPHA 310 in the (FRONT) pad of the centralizer 115, inthe direction of the electric moment (Ev) of the vertically polarizedslot antenna elements (205) (see FIG. 2A). The wire 515 is connected ina way that causes the transmitters and receivers (not shown) of the VPHA310 to repeatedly transmit signals in the direction of the wellbore(114), and repeatedly receive signals associated with the transmittedsignals after they have engaged the wellbore (114).

The transmitted and received signals are electromagnetic waves orsignals that engage the wellbore (114) by inducing signals into theformation. Formation properties can then be determined by measuring oranalyzing the electromagnetic waves or signals associated with thetransmitted signals. The wire 515 may be one or more wires, and is alsoconnected to the second receiver array (305-320) on the opposite (orBACK) side of the centralizer 115 (e.g., the HPVA 320 shown in FIG. 5C),forming a circuit that may be energized by an electrical source (notshown) from within the electronics section (130) or instrument section(140) of the tool (100). The source may be a battery or other sourcecapable of driving electrical current, and may be caused to drivecurrent by one or more processors in the electronics section (130) orinstrument section (140) of the tool (100) (not shown).

The electrical current in the wire 515 traverses the VPHA 310 and theHPVA 320 in the direction of their respective electric moments (Ev orEh) (see FIG. 2B), in a way that causes the transmitters and receivers(not shown) within the VPHA 310 and the HPVA 320 to transmit and receivesignals. The diagrams in FIGS. 5A-5C are only conceptual in nature, usedto illustrate example configurations and the operation of the system.The figures disclosed are not intended to limit the mechanicalconfigurations, antenna array (305-320) configurations, or circuitdesigns of the present disclosure.

Now that the components of the system and various example configurationsof the antenna arrays with the centralizer 115 have been illustrated,the method of obtaining quantitative measurements of resistivity andpermittivity will now be described.

FIG. 6 illustrates a method for simultaneously obtaining quantitativevertical and horizontal formation parameters according to the presentdisclosure. Referring to step 600 and using the example transmitters andreceivers of FIG. 3 for reference, one or more processors in theelectronics section (130) or instrument section (140) of the tool (100)may cause the one or more wires (515) to be energized by an electricalsource, thereby causing transmitters (T1 and T2) in one antenna array(i.e., one of the four antenna arrays 305-320) to transmit signals inthe direction of the wellbore (114).

After the transmitted signals have engaged the wellbore (114), at step605 the receivers (R1 and R2) will receive signals associated with thetransmitted signals. Also, simultaneously with transmitters (T1 and T2)at step 600, transmitters (T3 and T4) within the second antenna array(305-320) on the opposite side of the centralizer 115 (as described inFIGS. 5A-5C) will transmit signals in the direction of the wellbore(114), and the associated signals will be received at step 605 byreceivers (R3 and R4) in the second antenna array. The received signalsrepresent apparent quantitative formation measurement data (i.e.,measured apparent formation data) and may be used to determinequantitative formation properties such as the resistivity andpermittivity of the formation.

As described above with reference to FIGS. 5A-5C, the two antenna arraysdisposed on the opposite sides of the centralizer 115 may include any ofthe four combinations discussed above with reference to FIG. 3(305-320); however, if one side of the stabilizer pad 505 has avertically polarized array (e.g., array 305 or 315) the opposite padwill have a horizontally polarized array (e.g., array 310 or 320)disposed thereon. Accordingly, the quantitative formation propertiesthat are determined will be reflective of the formation properties inboth the vertical and horizontal directions, relative to the drillcollar 125.

Also, considering the rotation of the tool (100) in the wellbore, boththe horizontal and vertical arrays (305-320) on each side of thecentralizer 115 can be regarded as one tool (i.e., one electromagneticantenna) having equivalent vertical and horizontal magnetic moments, asdescribed with reference to FIGS. 2A-2B. As a result, while the toolrotates within the wellbore (114), the tool can be used to detect theformation properties at all azimuthal angles within the wellbore (114).

Referring again to the method illustrated in FIG. 6, once the signalsassociated with the transmitted signals have been received at step 605,they may be processed using one or more processors (not shown)associated with the surface equipment (105), electronics section (130),or instrument section (140) to obtain the compensated voltage (Vcomp) ofthe quantitative formation data. The one or more processors (not shown)may communicate with memory having instructions stored thereon forenabling the one or more processors to process the signals.

Using methods known in the art, the compensated voltage Vcomp can thenbe used to determine the phase and attenuation. Computations that can beused for determining the Vcomp, attenuation, and phase difference alongthe vertical and horizontal planes of the wellbore (114) formation areshown below:

${V_{comp} = {\frac{V_{T\; 1R\; 2}}{V_{T\; 1R\; 1}} \cdot \frac{V_{T\; 2R\; 1}}{V_{T\; 2R\; 2}}}},{{A\; T} = {20 \cdot {\log_{10}\left( {V_{comp}} \right)}}},{{P\; D} = {{ATAN}\; 2\left( {{{imag}\left( V_{comp} \right)},{{real}\left( V_{comp} \right)}} \right)}}$

${V_{comp} = {\frac{V_{T\; 3R\; 4}}{V_{T\; 3R\; 3}} \cdot \frac{V_{T\; 4R\; 3}}{V_{T\; 4R\; 4}}}},{{A\; T} = {20 \cdot {\log_{10}\left( {V_{comp}} \right)}}},{{PD} = {{ATAN}\; 2\left( {{{imag}\left( V_{comp} \right)},{{real}\left( V_{comp} \right)}} \right)}}$

As shown, the voltage compensation (Vcomp) for transmitters (T1-T4) andreceivers (R1-R4) of the two antenna arrays (305-320) can be used todetermine the attenuation (“AT” of the above equation) and the phasedifference (“PD” of the above equation) of the wellbore (114) formation.

Because the apparent formation measurement data is only the apparent,and not the real data, it is necessary to invert the apparent formationmeasurement data for each array (i.e., each of the vertical andhorizontal arrays on opposite sides of the tool, see FIG. 5A-5C). Usinginversion, the true formation measurement data (i.e., true vertical andhorizontal, phase difference and attenuation) may be obtained.

Referring to step 610 of FIG. 6, in one example OD or “zero dimension”inversion as known in the art can be used to obtain the true verticaland horizontal formation measurement data.

As discussed above, once the true phase difference and attenuation(i.e., true formation data) has been determined using the aboveequation, at step 615 using techniques known in the art, the trueformation data can be used to obtain the formation parameters such asthe resistivity and permittivity of the formation. Such known methodsfor determining these parameters include, using lookup tables or usingreal time processing based on the tool response.

Referring now to FIG. 7, a method of inverting the apparent vertical andapparent horizontal formation measurement data values using OD inversionis illustrated according to the present disclosure. The inversionprocess described below may be performed by one or more processors (notshown) associated with surface equipment (105) having an up holeprocessing unit, electronics section (130), or instrument section (140).The inversion method begins at step 705 by using the one or moreprocessors to obtain simulated formation measurement data (i.e., thesimulated attenuation and phase difference responses of the tool). Thesimulated formation measurement data is the modeled response data of thetool (100) with respect to known parameters of the formation to whichthe tool is being applied. Thus, the simulated formation measurementdata can be obtained by simulating or numerically modeling theinteraction between the tool and the formation within the wellbore 114.

After the simulated formation measurement data has been obtained, atstep 710 the simulated formation measurement data is compared with theapparent formation measurement data determined above. If at step 715 thedifference between the simulated formation measurement data and theapparent formation measurements exceed a predefined threshold, themethod at step 720 will determine and incrementally update a valuerepresenting the true formation measurement data by calculating aJacobian matrix as is known in the art.

Once the true formation measurement data has been determined at step720, and the difference between the simulated formation measurementvalues and the true formation measurement data does not exceed thepredefined threshold (after repeating steps 705 through 715 using thetrue formation measurement data), the true formation measurement data isoutput by the system as the true formation measurement data.

However, if after the initial comparison step at 715, the differencebetween the simulated formation measurement data and the apparentformation measurement data does not exceed a predefined threshold, theapparent formation measurement data is output as the true formationmeasurement data at step 725.

As a result, the tool can be used to simultaneously obtain quantitativemeasurements of the resistivity and permittivity of a formation in boththe vertical and horizontal directions within a wellbore. Also, byrotating the drill string (113) while taking the measurements, andtransmitting using higher frequencies, the vertical and horizontalresistivity and permittivity of the formation may be determined at allazimuthal angles around wellbore (114), in either oil or water basedmud.

The foregoing description of preferred and other embodiments is notintended to limit or restrict the scope or applicability of theinventive concepts conceived of by the Applicant. It will be appreciatedwith the benefit of the present disclosure that features described abovein accordance with any embodiment or aspect of the disclosed subjectmatter can be utilized, either alone or in combination, with any otherdescribed feature, in any other embodiment or aspect of the disclosedsubject matter.

In exchange for disclosing the inventive concepts contained herein, theApplicant desires all patent rights afforded by the appended claims.Therefore, it is intended that the appended claims include allmodifications and alterations to the full extent that they come withinthe scope of the following claims or the equivalents thereof.

What is claimed is:
 1. A method for measuring formation propertiesdownhole, the method comprising: firing, using at least one transmitterin each of a horizontally and vertically polarized array on oppositesides of a drill collar, signals in the direction of a downholeformation, the fired signals from the transmitters in the arrays beingfired simultaneously and engaging the downhole formation; receiving,using at least one receiver in each of the arrays, signals associatedwith the fired signals after the fired signals engage the downholeformation, the received signals representing apparent formationmeasurement data; determining, using the apparent formation measurementdata, true formation measurement data; and obtaining, using the trueformation measurement data, one or more vertical and horizontalformation parameters.
 2. The method of claim 1, wherein the vertical andhorizontal formation parameters include the vertical and horizontalresistivity and permittivity of the downhole formation.
 3. The method ofclaim 1, wherein the apparent formation measurement data includes thephase and attenuation of the apparent formation measurement data.
 4. Themethod of claim 1, wherein determining true formation measurement dataincludes: obtaining, simulated formation measurement data; comparing,the simulated formation measurement data with the apparent formationmeasurement data; updating, if the difference between the simulatedformation measurement data and the apparent formation measurement dataexceeds a threshold, true formation measurement data; and outputting, ifthe difference between the simulated formation measurement data and thetrue formation measurement data does not exceed the threshold, the trueformation measurement data.
 5. The method of claim 1, wherein engagingthe downhole formation comprises inducing signals into the downholeformation.
 6. The method of claim 1, wherein firing, using at least onetransmitter in each of a horizontally and vertically polarized array,includes firing high frequency signals.
 7. The method of claim 6,wherein high frequency signals comprise signals having a frequencybetween 10 MHz and 20 GHz.
 8. The method of claim 1, wherein thehorizontally and vertically polarized arrays are disposed on oppositesides of a centralizer disposed on the drill string.
 9. The method ofclaim 1, wherein determining the true formation measurement dataincludes updating the true formation measurement data.
 10. The method ofclaim 1, wherein the plurality of transmitters and receivers are filledwith an epoxy.
 11. A downhole tool, comprising: a drill string; a drillcollar disposed on the drill string; each of a horizontally andvertically polarized array disposed on opposite sides of the drillcollar and connected by one or more wires, the horizontally andvertically polarized arrays including a plurality of transmitters andreceivers; wherein, when the one or more wires are energized by a sourcethe one or more wires simultaneously cause a first transmitter of theplurality of transmitters in each of the arrays to fire signals in thedirection of a downhole formation, the fired signals from each of thefirst transmitters engaging the downhole formation; wherein, the one ormore wires are energized by the source to cause a first and secondreceiver in each of the arrays to receive signals associated with thesignals fired from the first transmitters after the fired signals haveengaged the downhole formation, the first receivers in each array beingdisposed between the first transmitters and second receivers, thereceived signals representing apparent formation data; wherein, when theone or more wires are energized by the source the one or more wiressimultaneously cause a second transmitter of the plurality oftransmitters in each of the arrays to fire signals in the direction ofthe downhole formation, the fired signals from each of the secondtransmitters engaging the downhole formation; wherein, the one or morewires are energized to cause the first and second receivers in each ofthe arrays to receive signals associated with the signals fired from thesecond transmitters after the fired signals have engaged the downholeformation, the second receivers in each array being disposed between thefirst receivers and the second transmitters, the received signalsrepresenting apparent formation measurement data; wherein, trueformation measurement data is determined using the apparent formationmeasurement data; and wherein, one or more vertical and horizontalformation parameters are obtained using the true formation measurementdata.
 12. The downhole tool of claim 11, wherein the vertical andhorizontal formation parameters include the vertical and horizontalresistivity and permittivity of the downhole formation.
 13. The downholetool of claim 11, wherein the apparent formation measurement dataincludes the phase and attenuation of the apparent formation measurementdata.
 14. The downhole tool of claim 11, wherein the true formationmeasurement data is determined by obtaining simulated formationmeasurement data by using one or more processors to simulate ornumerically model the interaction between the tool and the formationwithin the wellbore; wherein after the simulated formation measurementdata is obtained the one or more processors compare the simulatedformation measurement data with the apparent formation measurement data;wherein, if the one or more processors determine that the differencebetween the simulated formation measurement data and the apparentformation measurement data exceeds a threshold the true formationmeasurement data is determined; and wherein, if the one or moreprocessors determine that the difference between the simulated formationmeasurement data and the true formation measurement data does not exceedthe threshold, the true formation measurement data is output.
 15. Thedownhole tool of claim 11, wherein engaging the downhole formationcomprises inducing signals into the downhole formation.
 16. The downholetool of claim 11, wherein the first and second transmitters of theplurality of transmitters in each of the horizontally and verticallypolarized arrays fires high frequency signals.
 17. The downhole tool ofclaim 16, wherein high frequency signals comprise signals having afrequency between 10 MHz and 20 GHz.
 18. The downhole tool of claim 11,wherein the horizontally and vertically polarized arrays are disposed onopposite sides of a centralizer disposed on the drill string.
 19. Thedownhole tool of claim 11, wherein when the true formation measurementdata is determined the true formation measurement data is updated. 20.The downhole tool of claim 11, wherein the plurality of transmitters andreceivers are filled with an epoxy.